Kooperativer Bibliotheksverbund

UID:

Format: 1 online resource (304 p.)

Edition: 3rd ed.

ISBN: 1-283-29381-1 , 9786613293817 , 1-85617-930-3

Content: A quick reference for day-to-day work out on the rig or a handy study guide for drilling and well control certification courses, Formulas and Calculations for Drilling, Production and Workover has served a generation of oilfield professionals throughout their careers. Compact and readable, Formulas and Calculations for Drilling, Production and Workover, 3rd Edition is a problem solving time saving tool for the most basic or complex predicaments encountered in the field. All formulas and calculations are presented in easy-to-use, step-by-step order, virtually all the mathematics r

Note: Rev. ed. of: Formulas and calculations for drilling, production, and workover / Norton J. Lapeyrouse. , Front Cover; Formulas and Calculations for Drilling, Production, and Workover: All the Formulas You Need to Solve Drilling and Production Problems; Copyright; Contents; Preface; Chapter 1: Basic Equations; 1.0. Terminology; 1.1. Mud Weight MW (lb/ft3), Mud Weight MW (ppg), and Specific Gravity (SG) [USCS/British]; 1.2. Density ρ (kg/m3 or kg/liter), Mud Weight MW (N/m3 or N/liter), and Specific Gravity (SG) [SI-Metric]; 1.3. Hydrostatic Pressure (P) and (p) [USCS/British]; 1.4. Hydrostatic Pressure (P) and (p) [SI-Metric]; 1.5. Pressure Gradient (psi/ft), G (ppg) [USCS/British] , 1.6. Pressure Gradient G (SG) [SI-Metric]1.7. Equivalent Circulating ""Density"" ECD (ppg) [USCS/British]; 1.8. Equivalent Circulating ""Density"" ECD (N/liter) and ECD (SG) [SI-Metric]; 1.9. Mud Pump Output Q (bbl/stk) and q (gpm) [USCS/British]; 1.9.1. Triplex Pump; 1.9.2. Duplex Pump; 1.9.3. Hydraulic Horsepower; 1.10. Capacity Formulas; 1.10.1. Annular Capacity between Casing or Hole and Drill Pipe, Tubing, or Casing; 1.10.2. Annular Capacity between Casing and Multiple Strings of Tubing , 1.10.3. Capacity of Tubulars and Open Hole: Drill Pipe, Drill Collars, Tubing, Casing, Hole, and Any Cylindrical Object1.10.4. Amount of Cuttings Drilled per Foot of Hole Drilled; 1.11. Annular Velocity Van (ft/min); Metric Calculations; SI Unit Calculations; 1.12. Strokes per Minute (SPM) Required for a Given Annular Velocity; 1.13. Control Drilling; 1.14. Buoyancy Factor (BF); 1.15. Decrease When Pulling Pipe Out of the Hole; 1.15.1. When Pulling DRY Pipe; 1.15.2. When Pulling WET Pipe; 1.16. Loss of Overbalance Due to Falling Mud Level; 1.16.1. Feet of Pipe Pulled DRY to Lost Overbalance , 1.16.2. Feet of Pipe Pulled WET to Lose OverbalanceMetric Calculations; SI Unit Calculations; Formation Temperature (Tf); 1.17. Circulating Hydraulic Horsepower (HHP); 1.17.1. Rule of Thumb Formulas; 1.18. Pump Pressure/Pump Stroke Relationship (the Roughneck's Formula); Metric Calculation; SI Unit Calculation; 1.19. Cost per Foot; 1.20. Temperature Conversion Formulas; Convert Temperature, Fahrenheit (F) to Centigrade or Celsius (C); Convert Temperature, Centigrade or Celsius (C) to Fahrenheit; Convert Temperature, Centigrade, Celsius (C) to Kelvin (K) , Convert Temperature, Fahrenheit (F) to Rankine (R)Rule of Thumb Formulas for Temperature Conversion; Chapter 2: Basic Calculations; 2.0. Capacity, Volumes, and Strokes; 2.0.1. Capacity of Drill Pipe, HWDP, Casing, or Open Hole in bbl/ft; 2.0.2. Capacity of Casing or Open Hole between Drill Pipe, HWDP, or Casing in bbl/ft; 2.0.3. Capacity of Drill Pipe, HWDP, Casing, or Open Hole in ft/bbl; 2.0.4. Capacity of Casing or Open Hole between Drill Pipe, HWDP, or Casing in ft/bbl; 2.0.5. Volume of Drill Pipe, HWDP, Drill Collar, or Casing in bbl , 2.0.6. Volume between Drill Pipe, HWDP, or Casing, and the Casing or Open Hole in bbl , English

Additional Edition: ISBN 1-85617-929-X

Language: English

UID:

Format: 1 online resource (358 pages)

Edition: Fifth edition.

ISBN: 0-323-98475-4

Content: Updated for today's engineer, Formulas and Calculations for Drilling, Production, and Workover, Fifth Edition delivers the quick answers for daily petroleum challenges. Starting with a review of basic equations, calculations, and many worked examples, this reference offers a quick look up of topics such as drilling fluids, pressure control, and air and gas calculations. The formulas and calculations are provided in either English field units or in metric units. Additional topics include cementing, subsea considerations, well hydraulics, hydraulic fracturing methods, and drill string design limitations. New formulas include geothermal drilling, horizontal wells, and temperature workover. Formulas and Calculations for Drilling, Production, and Workover, Fifth Edition continues to save time and money for the oilfield worker and manager on the job with an easy layout and organization, helping you confidently conduct operations and evaluate the performance of your wells.

Note: Includes index. , Intro -- Formulas and Calculations for Drilling, Production, and Workover: All the Formulas You Need to Solve Drilling and Producti ... -- Copyright -- Contents -- Preface -- Prologue -- Chapter 1: Basic equations -- 1.1. Terminology -- 1.2. Mud weight MW (lb/ft3), mud weight MW (ppg), and specific gravity (SG) -- 1.3. Hydrostatic pressure (P) and (p) -- 1.4. Pressure gradient (psi/ft), G (ppg) -- 1.5. Mud pump output q (bbl/stk) and Q (gpm) -- 1.5.1. Triplex pump -- 1.5.2. Duplex pump -- 1.6. Hydraulic horsepower -- 1.7. Estimated weight of drill collars in AIR -- 1.8. Open hole and tubular capacity and displacement formulas -- 1.8.1. Capacity of open hole or tubulars -- 1.8.2. Displacement of tubulars -- 1.8.3. Annular capacity between casing or hole and drill pipe, tubing, or casing -- 1.8.4. Annular capacity between casing and multiple strings of tubing -- 1.9. Amount of cuttings drilled per foot of hole -- 1.10. Annular velocity (AV) -- 1.11. Pump output required in GPM for a desired annular velocity, ft/min -- 1.12. Bottoms-up formula -- 1.13. Pump pressure/pump stroke relationship (the Roughnecks formula) -- 1.14. Buoyancy factor (BF) -- 1.15. Formation temperature (Tf) -- 1.16. Temperature conversion formulas -- Appendix: Supplementary material -- Chapter 2: RIG calculations -- 2.1. Accumulator capacity -- 2.1.1. Usable volume per bottle -- 2.1.2. Surface application -- 2.1.3. Volume capacity of the accumulator bottle -- 2.1.4. Deepwater applications -- 2.1.5. Accumulator precharge pressure -- 2.2. Slug calculations -- 2.2.1. Barrels of slug required for a desired length of dry pipe -- 2.2.2. Weight of slug required for a desired length of dry pipe with a set volume of slug -- 2.2.3. Volume, height, and pressure gained because of placement of the slug in the drill pipe -- 2.2.4. The amount of dry pipe in feet after pumping the slug. , 2.3. Bulk density of cuttings using the mud balance -- 2.4. Drill string design -- 2.4.1. Estimated weight of the drill collars in air -- 2.4.2. Tensile strength of tubulars in lb (Ref.: API Spec 5D & -- 7) -- 2.4.3. Reduced tensile yield strength of tubulars in lb -- 2.4.4. Adjusted weight and length of the drill pipe and tool joints -- 2.4.5. Length of the BHA necessary for a desired weight on bit -- 2.4.6. Maximum length of the premium drill pipe that can be run into the hole with a specific BHA based on the margin of ... -- 2.4.7. Length of the premium drill pipe based on the overpull and slip crushing -- 2.4.7.1. Slip crushing -- 2.4.8. Design of a drill string for a specific set of well conditions -- 2.5. Depth of a washout in a drill pipe -- 2.6. Stuck pipe calculations -- 2.6.1. Calculate the number of days to quit fishing -- 2.6.2. Determine the length of the free pipe in feet and the free point constant -- 2.6.3. Stuck pipe overbalance guidelines -- 2.6.4. Force required to pull the differently stuck pipe free -- 2.7. Calculations required for placing spotting pills in an open hole annulus -- 2.7.1. Amount of spotting fluid pill in barrels required to cover the stuck point of the drill string or casing and the n ... -- 2.7.2. Determination of the length of an unweighted spotting fluid pill that will balance formation pressure in the annul ... -- 2.8. Line size for a low pressure system -- Appendix: Supplementary material -- References -- Bibliography -- Chapter 3: Pressure control -- 3.1. Normal kill sheet -- 3.2. Pressure chart: Prepare a chart with pressure and strokes -- 3.2.1. Use this technique for rigs that have digital pressure gauges -- 3.2.2. Use this technique for rigs that have analog pressure gauges -- 3.3. Kill sheet with a tapered string -- 3.4. Kill sheet for a highly deviated well. , 3.5. Maximum anticipated surface pressure -- 3.6. Trip margin (TM) -- 3.7. Sizing the diverter line -- 3.8. Fracture gradient (FG) -- 3.8.1. Fracture gradient determination-Surface application -- 3.8.2. Fracture gradient determination-Subsea application -- 3.9. Formation pressure tests -- 3.9.1. Precautions to be undertaken before testing -- 3.9.2. Testing to an equivalent mud weight (formation integrity test-FIT) -- 3.9.3. Testing to leak-off test pressure -- 3.9.4. Procedure to prepare the graph to record leak-off pressure data -- 3.9.5. Maximum allowable mud weight from leak-off test data -- 3.10. Kick tolerance (KT) -- 3.10.1. Kick tolerance intensity (KTI) -- 3.10.2. Kick tolerance volume (KTV) -- 3.10.3. Summary -- 3.11. Kick analysis -- 3.11.1. Formation pressure (FP) with the well shut-in on a kick -- 3.11.2. Bottom hole pressure (BHP) with the well shut-in on a kick -- 3.11.3. Shut-in drill pipe pressure (SIDPP) -- 3.11.4. Shut-in casing pressure (SICP) -- 3.11.5. Length of influx in ft -- 3.11.6. Estimated type of influx -- 3.12. Gas cut mud weight measurement calculations -- 3.12.1. Determine the original mud weight of a gas cut mud at the flowline -- 3.12.2. Determine the reduction in the mud weight at the flowline when a gas formation is drilled with no kick -- 3.13. Gas migration in a shut-in well -- 3.13.1. Gas migration -- 3.14. Hydrostatic pressure decrease at TD caused by formation fluid influx due to a kick -- 3.14.1. Hydrostatic pressure decrease -- 3.14.2. Maximum surface pressure from a gas kick in a water-base mud -- 3.14.3. Maximum pit gain from gas kick in a water-base mud -- 3.15. Maximum pressures when circulating out a kick (Moore equations) -- 3.15.1. Maximum pressure calculations -- 3.15.2. Summary of maximum pressures when circulating out a kick (Moore equations) -- 3.16. Gas flow into the wellbore. , 3.16.1. Gas flow into the wellbore -- 3.16.2. Gas flow through a choke -- 3.17. Pressure analysis -- 3.17.1. Gas expansion equation -- 3.17.2. Hydrostatic pressure exerted by each barrel of mud in the casing -- 3.17.3. Surface pressure during drill stem test (DST) -- 3.18. Stripping/snubbing calculations -- 3.18.1. Breakover point between stripping and snubbing -- 3.18.2. Minimum surface pressure before stripping is possible -- 3.18.3. Height gain from stripping into influx -- 3.18.4. Casing pressure increase from stripping into influx -- 3.18.5. Volume of mud that must be bled to maintain constant bottom hole pressure with a gas bubble rising -- 3.18.6. Maximum allowable surface pressure (MASP) governed by the formation -- 3.18.7. Maximum allowable surface pressure (MASP) governed by casing burst pressure -- 3.19. Subsea considerations -- 3.19.1. Casing pressure decrease when bringing well on choke -- 3.19.2. Pressure chart for bringing well on choke -- 3.19.3. Maximum allowable mud weight for subsea stack as derived from leak-off test data -- 3.19.4. Casing burst pressure-Subsea stack -- 3.19.5. Calculate choke line pressure loss in psi -- 3.19.6. Velocity through the choke line in ft/min -- 3.19.7. Adjusting choke line pressure loss for a higher mud weight in ppg -- 3.19.8. Minimum conductor casing setting depth in ft -- 3.19.9. Maximum mud weight with returns back to rig floor in ppg -- 3.19.10. Reduction in bottom hole pressure if riser is disconnected in psi -- 3.19.11. Bottom hole pressure when circulating out a kick in psi -- 3.20. Workover operations -- 3.20.1. Bullheading -- 3.20.2. Lubricate and bleed -- 3.21. Controlling gas migration -- 3.21.1. Drill pipe pressure method -- 3.21.2. Volumetric method to control gas migration -- 3.22. Gas lubrication -- 3.22.1. Gas lubrication-Volume method -- 3.22.2. Gas lubrication-Pressure method. , 3.23. Annular stripping procedures -- 3.23.1. Strip and bleed procedure -- 3.23.2. Combined stripping/volumetric procedure -- 3.23.3. Worksheet -- 3.24. Barite plug -- Appendix: Supplementary material -- Bibliography -- Chapter 4: Drilling fluids -- 4.1. Mud density increase and volume change -- 4.1.1. Field procedure for determining the specific gravity of barite -- 4.1.2. Increase mud density-No base liquid added and no volume limit -- 4.1.3. Increase mud weight-No base liquid added but limit final volume -- 4.1.4. Increase the mud weight-With base liquid added and no volume limit -- 4.1.5. Increase mud weight-With base liquid added but limit final volume -- 4.1.6. Increase mud weight-With base liquid added but limit final volume and limited weight material inventory -- 4.1.7. Increase mud weight to a maximum mud weight with base liquid added but with limited weight material inventory -- 4.2. Mud weight reduction with base liquid dilution -- 4.2.1. Mud weight reduction with base liquid -- 4.3. Mixing fluids of different densities -- 4.3.1. Mixing fluids of different densities formula -- 4.4. Oil-based mud calculations -- 4.4.1. Calculate the starting volume of liquid (base oil plus water) required to prepare a desired final volume of nonaqu ... -- 4.4.2. Oil/water ratio from retort data -- 4.4.3. Change the OWR -- 4.5. Solids analysis -- 4.6. Solids fractions (barite treated muds) -- 4.6.1. Calculate the maximum recommended solids fraction in % based on the mud weight -- 4.6.2. Calculate the maximum recommended LGS fraction in % based on the mud weight -- 4.7. Dilution of mud system -- 4.7.1. Calculate the volume of dilution in bbl required to reduce the solids content in the mud system -- 4.7.2. Displacement-Barrels of water/slurry required -- 4.8. Evaluation of hydrocyclones. , 4.8.1. Calculate the mass of solids (for an unweighted mud) and the volume of water discarded by one cone of a hydrocyclo.

Additional Edition: Print version: Lyons, , PE,, William C. Formulas and Calculations for Drilling, Production, and Workover San Diego : Elsevier Science & Technology,c2023 ISBN 9780323905497

Language: English

UID:

Format: 1 online resource (233 p.)

Edition: 2nd ed.

ISBN: 1-281-03667-6 , 9786611036676 , 0-08-050676-3

Content: The most complete manual of its kind, this handy book gives you all the formulas and calculations you are likely to need in drilling operations. New updated material includes conversion tables into metric. Separate chapters deal with calculations for drilling fluids, pressure control, and engineering. Example calculations are provided throughout.Presented in easy-to-use, step-by-step order, Formulas and Calculations is a quick reference for day-to-day work out on the rig. It also serves as a handy study guide for drilling and well control certification courses. Virtually all the m

Note: Includes index. , Cover; Formulas and Calculations for Drilling, Production, and Workover; Copyright Page; CONTENTS; PREFACE; CHAPTER 1. BASIC FORMULAS; Pressure Gradient; Hydrostatic Pressure; Converting Pressure into Mud Weight; Specific Gravity; Equivalent Circulating Density; Maximum Allowable Mud Weight; Pump Output; Annular Velocity; Capacity Formulas; Control Drilling; Buoyancy Factor; Hydrostatic Pressure Decrease When Pulling Pipe out of the Hole; Loss of Overbalance Due to Falling Mud Level; Formation Temperature; Hydraulic Horsepower; Drill Pipe/Drill Collar Calculations , Pump Pressure/Pump Stroke RelationshipCost per Foot; Temperature Conversion Formulas; CHAPTER 2. BASIC CALCULATIONS; Volumes and Strokes; Slug Calculations; Accumulator Capacity; Bulk Density of Cuttings; Drill String Design (Limitations); Ton-Mile Calculations; Cementing Calculations; Weighted Cement Calculations; Calculations for the Number of Sacks of Cement Required; Calculations for the Number of Feet to Be Cemented; Setting a Balanced Cement Plug; Differential Hydrostatic Pressure Between Cement in the Annulus and Mud Inside the Casing; Hydraulicing Casing; Depth of a Washout , English

Additional Edition: ISBN 0-7506-7452-0

Language: English

UID:

Format: vii, 224 S. , graph. Darst.

Edition: 2nd ed.

ISBN: 0750674520

Content: Content: Basic formulas, basic calculations, drilling fluids, pressure control, engineering calculations

Note: MAB0014.001: M 04.0536

UID:

Format: VIII, 216 S.

ISBN: 0884150119

Language: Undetermined

UID:

Format: 1 online resource (358 pages)

Edition: Fifth edition.

ISBN: 0-323-98475-4

Content: Updated for today's engineer, Formulas and Calculations for Drilling, Production, and Workover, Fifth Edition delivers the quick answers for daily petroleum challenges. Starting with a review of basic equations, calculations, and many worked examples, this reference offers a quick look up of topics such as drilling fluids, pressure control, and air and gas calculations. The formulas and calculations are provided in either English field units or in metric units. Additional topics include cementing, subsea considerations, well hydraulics, hydraulic fracturing methods, and drill string design limitations. New formulas include geothermal drilling, horizontal wells, and temperature workover. Formulas and Calculations for Drilling, Production, and Workover, Fifth Edition continues to save time and money for the oilfield worker and manager on the job with an easy layout and organization, helping you confidently conduct operations and evaluate the performance of your wells.

Note: Includes index. , Intro -- Formulas and Calculations for Drilling, Production, and Workover: All the Formulas You Need to Solve Drilling and Producti ... -- Copyright -- Contents -- Preface -- Prologue -- Chapter 1: Basic equations -- 1.1. Terminology -- 1.2. Mud weight MW (lb/ft3), mud weight MW (ppg), and specific gravity (SG) -- 1.3. Hydrostatic pressure (P) and (p) -- 1.4. Pressure gradient (psi/ft), G (ppg) -- 1.5. Mud pump output q (bbl/stk) and Q (gpm) -- 1.5.1. Triplex pump -- 1.5.2. Duplex pump -- 1.6. Hydraulic horsepower -- 1.7. Estimated weight of drill collars in AIR -- 1.8. Open hole and tubular capacity and displacement formulas -- 1.8.1. Capacity of open hole or tubulars -- 1.8.2. Displacement of tubulars -- 1.8.3. Annular capacity between casing or hole and drill pipe, tubing, or casing -- 1.8.4. Annular capacity between casing and multiple strings of tubing -- 1.9. Amount of cuttings drilled per foot of hole -- 1.10. Annular velocity (AV) -- 1.11. Pump output required in GPM for a desired annular velocity, ft/min -- 1.12. Bottoms-up formula -- 1.13. Pump pressure/pump stroke relationship (the Roughnecks formula) -- 1.14. Buoyancy factor (BF) -- 1.15. Formation temperature (Tf) -- 1.16. Temperature conversion formulas -- Appendix: Supplementary material -- Chapter 2: RIG calculations -- 2.1. Accumulator capacity -- 2.1.1. Usable volume per bottle -- 2.1.2. Surface application -- 2.1.3. Volume capacity of the accumulator bottle -- 2.1.4. Deepwater applications -- 2.1.5. Accumulator precharge pressure -- 2.2. Slug calculations -- 2.2.1. Barrels of slug required for a desired length of dry pipe -- 2.2.2. Weight of slug required for a desired length of dry pipe with a set volume of slug -- 2.2.3. Volume, height, and pressure gained because of placement of the slug in the drill pipe -- 2.2.4. The amount of dry pipe in feet after pumping the slug. , 2.3. Bulk density of cuttings using the mud balance -- 2.4. Drill string design -- 2.4.1. Estimated weight of the drill collars in air -- 2.4.2. Tensile strength of tubulars in lb (Ref.: API Spec 5D & -- 7) -- 2.4.3. Reduced tensile yield strength of tubulars in lb -- 2.4.4. Adjusted weight and length of the drill pipe and tool joints -- 2.4.5. Length of the BHA necessary for a desired weight on bit -- 2.4.6. Maximum length of the premium drill pipe that can be run into the hole with a specific BHA based on the margin of ... -- 2.4.7. Length of the premium drill pipe based on the overpull and slip crushing -- 2.4.7.1. Slip crushing -- 2.4.8. Design of a drill string for a specific set of well conditions -- 2.5. Depth of a washout in a drill pipe -- 2.6. Stuck pipe calculations -- 2.6.1. Calculate the number of days to quit fishing -- 2.6.2. Determine the length of the free pipe in feet and the free point constant -- 2.6.3. Stuck pipe overbalance guidelines -- 2.6.4. Force required to pull the differently stuck pipe free -- 2.7. Calculations required for placing spotting pills in an open hole annulus -- 2.7.1. Amount of spotting fluid pill in barrels required to cover the stuck point of the drill string or casing and the n ... -- 2.7.2. Determination of the length of an unweighted spotting fluid pill that will balance formation pressure in the annul ... -- 2.8. Line size for a low pressure system -- Appendix: Supplementary material -- References -- Bibliography -- Chapter 3: Pressure control -- 3.1. Normal kill sheet -- 3.2. Pressure chart: Prepare a chart with pressure and strokes -- 3.2.1. Use this technique for rigs that have digital pressure gauges -- 3.2.2. Use this technique for rigs that have analog pressure gauges -- 3.3. Kill sheet with a tapered string -- 3.4. Kill sheet for a highly deviated well. , 3.5. Maximum anticipated surface pressure -- 3.6. Trip margin (TM) -- 3.7. Sizing the diverter line -- 3.8. Fracture gradient (FG) -- 3.8.1. Fracture gradient determination-Surface application -- 3.8.2. Fracture gradient determination-Subsea application -- 3.9. Formation pressure tests -- 3.9.1. Precautions to be undertaken before testing -- 3.9.2. Testing to an equivalent mud weight (formation integrity test-FIT) -- 3.9.3. Testing to leak-off test pressure -- 3.9.4. Procedure to prepare the graph to record leak-off pressure data -- 3.9.5. Maximum allowable mud weight from leak-off test data -- 3.10. Kick tolerance (KT) -- 3.10.1. Kick tolerance intensity (KTI) -- 3.10.2. Kick tolerance volume (KTV) -- 3.10.3. Summary -- 3.11. Kick analysis -- 3.11.1. Formation pressure (FP) with the well shut-in on a kick -- 3.11.2. Bottom hole pressure (BHP) with the well shut-in on a kick -- 3.11.3. Shut-in drill pipe pressure (SIDPP) -- 3.11.4. Shut-in casing pressure (SICP) -- 3.11.5. Length of influx in ft -- 3.11.6. Estimated type of influx -- 3.12. Gas cut mud weight measurement calculations -- 3.12.1. Determine the original mud weight of a gas cut mud at the flowline -- 3.12.2. Determine the reduction in the mud weight at the flowline when a gas formation is drilled with no kick -- 3.13. Gas migration in a shut-in well -- 3.13.1. Gas migration -- 3.14. Hydrostatic pressure decrease at TD caused by formation fluid influx due to a kick -- 3.14.1. Hydrostatic pressure decrease -- 3.14.2. Maximum surface pressure from a gas kick in a water-base mud -- 3.14.3. Maximum pit gain from gas kick in a water-base mud -- 3.15. Maximum pressures when circulating out a kick (Moore equations) -- 3.15.1. Maximum pressure calculations -- 3.15.2. Summary of maximum pressures when circulating out a kick (Moore equations) -- 3.16. Gas flow into the wellbore. , 3.16.1. Gas flow into the wellbore -- 3.16.2. Gas flow through a choke -- 3.17. Pressure analysis -- 3.17.1. Gas expansion equation -- 3.17.2. Hydrostatic pressure exerted by each barrel of mud in the casing -- 3.17.3. Surface pressure during drill stem test (DST) -- 3.18. Stripping/snubbing calculations -- 3.18.1. Breakover point between stripping and snubbing -- 3.18.2. Minimum surface pressure before stripping is possible -- 3.18.3. Height gain from stripping into influx -- 3.18.4. Casing pressure increase from stripping into influx -- 3.18.5. Volume of mud that must be bled to maintain constant bottom hole pressure with a gas bubble rising -- 3.18.6. Maximum allowable surface pressure (MASP) governed by the formation -- 3.18.7. Maximum allowable surface pressure (MASP) governed by casing burst pressure -- 3.19. Subsea considerations -- 3.19.1. Casing pressure decrease when bringing well on choke -- 3.19.2. Pressure chart for bringing well on choke -- 3.19.3. Maximum allowable mud weight for subsea stack as derived from leak-off test data -- 3.19.4. Casing burst pressure-Subsea stack -- 3.19.5. Calculate choke line pressure loss in psi -- 3.19.6. Velocity through the choke line in ft/min -- 3.19.7. Adjusting choke line pressure loss for a higher mud weight in ppg -- 3.19.8. Minimum conductor casing setting depth in ft -- 3.19.9. Maximum mud weight with returns back to rig floor in ppg -- 3.19.10. Reduction in bottom hole pressure if riser is disconnected in psi -- 3.19.11. Bottom hole pressure when circulating out a kick in psi -- 3.20. Workover operations -- 3.20.1. Bullheading -- 3.20.2. Lubricate and bleed -- 3.21. Controlling gas migration -- 3.21.1. Drill pipe pressure method -- 3.21.2. Volumetric method to control gas migration -- 3.22. Gas lubrication -- 3.22.1. Gas lubrication-Volume method -- 3.22.2. Gas lubrication-Pressure method. , 3.23. Annular stripping procedures -- 3.23.1. Strip and bleed procedure -- 3.23.2. Combined stripping/volumetric procedure -- 3.23.3. Worksheet -- 3.24. Barite plug -- Appendix: Supplementary material -- Bibliography -- Chapter 4: Drilling fluids -- 4.1. Mud density increase and volume change -- 4.1.1. Field procedure for determining the specific gravity of barite -- 4.1.2. Increase mud density-No base liquid added and no volume limit -- 4.1.3. Increase mud weight-No base liquid added but limit final volume -- 4.1.4. Increase the mud weight-With base liquid added and no volume limit -- 4.1.5. Increase mud weight-With base liquid added but limit final volume -- 4.1.6. Increase mud weight-With base liquid added but limit final volume and limited weight material inventory -- 4.1.7. Increase mud weight to a maximum mud weight with base liquid added but with limited weight material inventory -- 4.2. Mud weight reduction with base liquid dilution -- 4.2.1. Mud weight reduction with base liquid -- 4.3. Mixing fluids of different densities -- 4.3.1. Mixing fluids of different densities formula -- 4.4. Oil-based mud calculations -- 4.4.1. Calculate the starting volume of liquid (base oil plus water) required to prepare a desired final volume of nonaqu ... -- 4.4.2. Oil/water ratio from retort data -- 4.4.3. Change the OWR -- 4.5. Solids analysis -- 4.6. Solids fractions (barite treated muds) -- 4.6.1. Calculate the maximum recommended solids fraction in % based on the mud weight -- 4.6.2. Calculate the maximum recommended LGS fraction in % based on the mud weight -- 4.7. Dilution of mud system -- 4.7.1. Calculate the volume of dilution in bbl required to reduce the solids content in the mud system -- 4.7.2. Displacement-Barrels of water/slurry required -- 4.8. Evaluation of hydrocyclones. , 4.8.1. Calculate the mass of solids (for an unweighted mud) and the volume of water discarded by one cone of a hydrocyclo.

Additional Edition: Print version: Lyons, , PE,, William C. Formulas and Calculations for Drilling, Production, and Workover San Diego : Elsevier Science & Technology,c2023 ISBN 9780323905497

Language: English

UID:

Format: vii, 224 p. : , ill.

Edition: 2nd ed.

Edition: Electronic reproduction. Ann Arbor, MI : ProQuest, 2016. Available via World Wide Web. Access may be limited to ProQuest affiliated libraries.

Note: Includes index.

Language: English

Keywords: Electronic books.

URL: Click to View

UID:

Format: 1 online resource (358 pages)

Edition: Fifth edition.

ISBN: 0-323-98475-4

Content: Updated for today's engineer, Formulas and Calculations for Drilling, Production, and Workover, Fifth Edition delivers the quick answers for daily petroleum challenges. Starting with a review of basic equations, calculations, and many worked examples, this reference offers a quick look up of topics such as drilling fluids, pressure control, and air and gas calculations. The formulas and calculations are provided in either English field units or in metric units. Additional topics include cementing, subsea considerations, well hydraulics, hydraulic fracturing methods, and drill string design limitations. New formulas include geothermal drilling, horizontal wells, and temperature workover. Formulas and Calculations for Drilling, Production, and Workover, Fifth Edition continues to save time and money for the oilfield worker and manager on the job with an easy layout and organization, helping you confidently conduct operations and evaluate the performance of your wells.

Note: Includes index. , Intro -- Formulas and Calculations for Drilling, Production, and Workover: All the Formulas You Need to Solve Drilling and Producti ... -- Copyright -- Contents -- Preface -- Prologue -- Chapter 1: Basic equations -- 1.1. Terminology -- 1.2. Mud weight MW (lb/ft3), mud weight MW (ppg), and specific gravity (SG) -- 1.3. Hydrostatic pressure (P) and (p) -- 1.4. Pressure gradient (psi/ft), G (ppg) -- 1.5. Mud pump output q (bbl/stk) and Q (gpm) -- 1.5.1. Triplex pump -- 1.5.2. Duplex pump -- 1.6. Hydraulic horsepower -- 1.7. Estimated weight of drill collars in AIR -- 1.8. Open hole and tubular capacity and displacement formulas -- 1.8.1. Capacity of open hole or tubulars -- 1.8.2. Displacement of tubulars -- 1.8.3. Annular capacity between casing or hole and drill pipe, tubing, or casing -- 1.8.4. Annular capacity between casing and multiple strings of tubing -- 1.9. Amount of cuttings drilled per foot of hole -- 1.10. Annular velocity (AV) -- 1.11. Pump output required in GPM for a desired annular velocity, ft/min -- 1.12. Bottoms-up formula -- 1.13. Pump pressure/pump stroke relationship (the Roughnecks formula) -- 1.14. Buoyancy factor (BF) -- 1.15. Formation temperature (Tf) -- 1.16. Temperature conversion formulas -- Appendix: Supplementary material -- Chapter 2: RIG calculations -- 2.1. Accumulator capacity -- 2.1.1. Usable volume per bottle -- 2.1.2. Surface application -- 2.1.3. Volume capacity of the accumulator bottle -- 2.1.4. Deepwater applications -- 2.1.5. Accumulator precharge pressure -- 2.2. Slug calculations -- 2.2.1. Barrels of slug required for a desired length of dry pipe -- 2.2.2. Weight of slug required for a desired length of dry pipe with a set volume of slug -- 2.2.3. Volume, height, and pressure gained because of placement of the slug in the drill pipe -- 2.2.4. The amount of dry pipe in feet after pumping the slug. , 2.3. Bulk density of cuttings using the mud balance -- 2.4. Drill string design -- 2.4.1. Estimated weight of the drill collars in air -- 2.4.2. Tensile strength of tubulars in lb (Ref.: API Spec 5D & -- 7) -- 2.4.3. Reduced tensile yield strength of tubulars in lb -- 2.4.4. Adjusted weight and length of the drill pipe and tool joints -- 2.4.5. Length of the BHA necessary for a desired weight on bit -- 2.4.6. Maximum length of the premium drill pipe that can be run into the hole with a specific BHA based on the margin of ... -- 2.4.7. Length of the premium drill pipe based on the overpull and slip crushing -- 2.4.7.1. Slip crushing -- 2.4.8. Design of a drill string for a specific set of well conditions -- 2.5. Depth of a washout in a drill pipe -- 2.6. Stuck pipe calculations -- 2.6.1. Calculate the number of days to quit fishing -- 2.6.2. Determine the length of the free pipe in feet and the free point constant -- 2.6.3. Stuck pipe overbalance guidelines -- 2.6.4. Force required to pull the differently stuck pipe free -- 2.7. Calculations required for placing spotting pills in an open hole annulus -- 2.7.1. Amount of spotting fluid pill in barrels required to cover the stuck point of the drill string or casing and the n ... -- 2.7.2. Determination of the length of an unweighted spotting fluid pill that will balance formation pressure in the annul ... -- 2.8. Line size for a low pressure system -- Appendix: Supplementary material -- References -- Bibliography -- Chapter 3: Pressure control -- 3.1. Normal kill sheet -- 3.2. Pressure chart: Prepare a chart with pressure and strokes -- 3.2.1. Use this technique for rigs that have digital pressure gauges -- 3.2.2. Use this technique for rigs that have analog pressure gauges -- 3.3. Kill sheet with a tapered string -- 3.4. Kill sheet for a highly deviated well. , 3.5. Maximum anticipated surface pressure -- 3.6. Trip margin (TM) -- 3.7. Sizing the diverter line -- 3.8. Fracture gradient (FG) -- 3.8.1. Fracture gradient determination-Surface application -- 3.8.2. Fracture gradient determination-Subsea application -- 3.9. Formation pressure tests -- 3.9.1. Precautions to be undertaken before testing -- 3.9.2. Testing to an equivalent mud weight (formation integrity test-FIT) -- 3.9.3. Testing to leak-off test pressure -- 3.9.4. Procedure to prepare the graph to record leak-off pressure data -- 3.9.5. Maximum allowable mud weight from leak-off test data -- 3.10. Kick tolerance (KT) -- 3.10.1. Kick tolerance intensity (KTI) -- 3.10.2. Kick tolerance volume (KTV) -- 3.10.3. Summary -- 3.11. Kick analysis -- 3.11.1. Formation pressure (FP) with the well shut-in on a kick -- 3.11.2. Bottom hole pressure (BHP) with the well shut-in on a kick -- 3.11.3. Shut-in drill pipe pressure (SIDPP) -- 3.11.4. Shut-in casing pressure (SICP) -- 3.11.5. Length of influx in ft -- 3.11.6. Estimated type of influx -- 3.12. Gas cut mud weight measurement calculations -- 3.12.1. Determine the original mud weight of a gas cut mud at the flowline -- 3.12.2. Determine the reduction in the mud weight at the flowline when a gas formation is drilled with no kick -- 3.13. Gas migration in a shut-in well -- 3.13.1. Gas migration -- 3.14. Hydrostatic pressure decrease at TD caused by formation fluid influx due to a kick -- 3.14.1. Hydrostatic pressure decrease -- 3.14.2. Maximum surface pressure from a gas kick in a water-base mud -- 3.14.3. Maximum pit gain from gas kick in a water-base mud -- 3.15. Maximum pressures when circulating out a kick (Moore equations) -- 3.15.1. Maximum pressure calculations -- 3.15.2. Summary of maximum pressures when circulating out a kick (Moore equations) -- 3.16. Gas flow into the wellbore. , 3.16.1. Gas flow into the wellbore -- 3.16.2. Gas flow through a choke -- 3.17. Pressure analysis -- 3.17.1. Gas expansion equation -- 3.17.2. Hydrostatic pressure exerted by each barrel of mud in the casing -- 3.17.3. Surface pressure during drill stem test (DST) -- 3.18. Stripping/snubbing calculations -- 3.18.1. Breakover point between stripping and snubbing -- 3.18.2. Minimum surface pressure before stripping is possible -- 3.18.3. Height gain from stripping into influx -- 3.18.4. Casing pressure increase from stripping into influx -- 3.18.5. Volume of mud that must be bled to maintain constant bottom hole pressure with a gas bubble rising -- 3.18.6. Maximum allowable surface pressure (MASP) governed by the formation -- 3.18.7. Maximum allowable surface pressure (MASP) governed by casing burst pressure -- 3.19. Subsea considerations -- 3.19.1. Casing pressure decrease when bringing well on choke -- 3.19.2. Pressure chart for bringing well on choke -- 3.19.3. Maximum allowable mud weight for subsea stack as derived from leak-off test data -- 3.19.4. Casing burst pressure-Subsea stack -- 3.19.5. Calculate choke line pressure loss in psi -- 3.19.6. Velocity through the choke line in ft/min -- 3.19.7. Adjusting choke line pressure loss for a higher mud weight in ppg -- 3.19.8. Minimum conductor casing setting depth in ft -- 3.19.9. Maximum mud weight with returns back to rig floor in ppg -- 3.19.10. Reduction in bottom hole pressure if riser is disconnected in psi -- 3.19.11. Bottom hole pressure when circulating out a kick in psi -- 3.20. Workover operations -- 3.20.1. Bullheading -- 3.20.2. Lubricate and bleed -- 3.21. Controlling gas migration -- 3.21.1. Drill pipe pressure method -- 3.21.2. Volumetric method to control gas migration -- 3.22. Gas lubrication -- 3.22.1. Gas lubrication-Volume method -- 3.22.2. Gas lubrication-Pressure method. , 3.23. Annular stripping procedures -- 3.23.1. Strip and bleed procedure -- 3.23.2. Combined stripping/volumetric procedure -- 3.23.3. Worksheet -- 3.24. Barite plug -- Appendix: Supplementary material -- Bibliography -- Chapter 4: Drilling fluids -- 4.1. Mud density increase and volume change -- 4.1.1. Field procedure for determining the specific gravity of barite -- 4.1.2. Increase mud density-No base liquid added and no volume limit -- 4.1.3. Increase mud weight-No base liquid added but limit final volume -- 4.1.4. Increase the mud weight-With base liquid added and no volume limit -- 4.1.5. Increase mud weight-With base liquid added but limit final volume -- 4.1.6. Increase mud weight-With base liquid added but limit final volume and limited weight material inventory -- 4.1.7. Increase mud weight to a maximum mud weight with base liquid added but with limited weight material inventory -- 4.2. Mud weight reduction with base liquid dilution -- 4.2.1. Mud weight reduction with base liquid -- 4.3. Mixing fluids of different densities -- 4.3.1. Mixing fluids of different densities formula -- 4.4. Oil-based mud calculations -- 4.4.1. Calculate the starting volume of liquid (base oil plus water) required to prepare a desired final volume of nonaqu ... -- 4.4.2. Oil/water ratio from retort data -- 4.4.3. Change the OWR -- 4.5. Solids analysis -- 4.6. Solids fractions (barite treated muds) -- 4.6.1. Calculate the maximum recommended solids fraction in % based on the mud weight -- 4.6.2. Calculate the maximum recommended LGS fraction in % based on the mud weight -- 4.7. Dilution of mud system -- 4.7.1. Calculate the volume of dilution in bbl required to reduce the solids content in the mud system -- 4.7.2. Displacement-Barrels of water/slurry required -- 4.8. Evaluation of hydrocyclones. , 4.8.1. Calculate the mass of solids (for an unweighted mud) and the volume of water discarded by one cone of a hydrocyclo.

Additional Edition: Print version: Lyons, , PE,, William C. Formulas and Calculations for Drilling, Production, and Workover San Diego : Elsevier Science & Technology,c2023 ISBN 9780323905497

Language: English